Drain apparatus for a subsea pipeline

ABSTRACT

The present invention provides a drain apparatus ( 200 ) for use in a subsea pipeline to remove liquid from a multiphase flow in the subsea pipeline. The drain apparatus comprises a first channel ( 20 ) for carrying a multiphase flow comprising liquid and gas phases; and liquid extraction means ( 11, 12, 14, 18 ) for extracting the liquid phase from the multiphase flow in the first channel ( 20 ). The internal diameter of the first channel ( 20 ) is substantially the same as an internal diameter of a subsea pipe arranged to carry the multiphase flow in the subsea pipeline, such that a pig travelling along the subsea pipe can pass through the first channel ( 20 ). The present invention also provides a subsea pipeline comprising a subsea pipe for transporting a multiphase flow subsea; and at least one drain. The at least one drain is disposed partway along a gradient in the subsea pipe to reduce liquid holdup.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application is a U.S. national phase application under 35U.S.C. § 371 of International Application No. PCT/GB2017/052463, filedon Aug. 21, 2017 and published as WO 2018/033758 A1 on Feb. 22, 2018,which claims priority to GB Application No. 1614196.2, filed on Aug. 19,2016, and GB Application No. 1706795.0, filed on Apr. 28, 2017. Thecontent of each of these related applications is incorporated herein byreference in its entirety.

FIELD

The present invention relates to a drain apparatus and a subseapipeline. More particularly, the present invention relates to a drainapparatus for use in the subsea pipeline.

BACKGROUND

When transporting production gas (which can be later processed intoLiquefied Natural Gas (LNG)) along a subsea pipeline, water and otherliquid components or mixtures precipitate out of the multiphase flow dueto heat and pressure loss. This results in a reduction in pressuredriving the system due to the gravitational effect on the condensingwater, which means generally production gas cannot naturally flow morethan about 80-140 km from a well head. Furthermore, the effect, known as“slugging”, increases the back pressure on the well and shortens theproduction plateau, where it would have been much greater if liquids hadnot been in the system (in other words, a “dry gas” system).

To solve this problem, both increasing and decreasing the bore of themain carrier pipe within the pipeline have been tried. However,increasing the bore was found to make the slugging worse due to anincrease in gravitational pressure losses. Decreasing the bore was foundto increase pressure loss due to friction.

Therefore, it is necessary to remove as much liquid from the multiphaseflow as possible, as early as possible. To that end, it is known toincorporate a single separator at the well head. However, this stilldoes not produce a pseudo dry gas system. Moreover, it is known to usesubsea drains (or, “Low Point Drains” (LPDs)), positioned at the lowestpart of a gradient, to remove liquid flowing back down the pipe in thepipeline that precipitated out due to temperature and pressurevariations. However, the particular designs of these LPDs, and theirlocation, is shown not to have had a great effect on system efficiency,as indicated by comparing the plots represented by diamonds and squaresin FIG. 17 . Moreover, present designs of LPDs do not allow continuouspigging operations, with subsequent negative effect on the system'sintegrity.

Minimising the effect of gravitational pressure losses enables pipelinesto have pipes with greater bore diameters, which in turn lowers thepressure drop per unit distance. Reducing the pressure drop alsoincreases the production plateau and allows more resources to beextracted from the ground. Aspects of the present invention aim toaddress one or more of the aforementioned drawbacks inherent in priorart subsea pipelines, while still allowing continuous piggingoperations.

SUMMARY

According to a first aspect of the present invention, there is provideda drain apparatus for use in a subsea pipeline to remove liquid from amultiphase flow in the subsea pipeline, the drain apparatus comprising:

-   -   a first channel for carrying a multiphase flow comprising liquid        and gas phases; and    -   liquid extraction means for extracting the liquid phase from the        multiphase flow in the first channel,

wherein the internal diameter of the first channel is substantially thesame as an internal diameter of a subsea pipe arranged to carry themultiphase flow in the subsea pipeline, such that a pig travelling alongthe subsea pipe can pass through the first channel.

Advantageously, the first aspect provides a means for transporting gasgreater distances by removing liquid from a subsea pipe in a subseapipeline at any chosen point along the length of the subsea pipe. Bybeing able to be positioned anywhere along the subsea pipe, rather thanat the well head, more liquid can be removed from the system. The drainapparatus can be positioned anywhere along the subsea pipe by virtue ofit being configured to allow pigging operations to continueuninterrupted between a well head and a terminal on the land.

The liquid extraction means may be configured so as not to permit themultiphase flow to bypass the pig as the pig passes through the firstchannel, such that a pressure differential can be maintained across thepig. In some embodiments, the liquid extraction means comprises at leastone opening formed in a wall of the first channel to permit liquid to beextracted through the at least one opening, and a distance between thefurthest downstream point of the at least one opening and the furthestupstream point of the at least one opening is less than 1.5 times theinternal diameter of the first channel. For example, in some embodimentsthe distance between the furthest downstream point of the at least oneopening and the furthest upstream point of the at least one opening isless than 0.8 times the internal diameter of the first channel.

The drain apparatus may be installed in a subsea pipeline, and the drainapparatus may be disposed partway along a gradient in the subsea pipe toreduce liquid holdup.

The liquid extraction means may be a slug catcher or a separator.

The liquid extraction means may comprise an inlet to receive liquid fromthe first channel, and a chamber in fluid communication with the inlet.

The liquid extraction means may be offset from the longitudinal axis ofthe first channel.

The drain apparatus may further comprise at least one valve arranged toblock the inlet in a first mode of operation and the first channel in asecond mode of operation.

The drain apparatus may further comprise:

-   -   a second channel configured to bypass the first channel,

wherein the liquid extraction means is disposed on the second channel.

The inlet may be formed in a wall of the first channel.

The liquid extraction means may comprise an outlet in fluidcommunication with the chamber for removing liquid from the drainapparatus.

The drain apparatus may further comprise:

-   -   first and second inlets formed in a wall of the first channel        along the longitudinal axis of the first channel;    -   a baffle arranged to divide the chamber into first and second        chambers, wherein the first inlet is arranged in the first        chamber and the second inlet is arranged in the second chamber;        and    -   a conduit disposed outside the chamber and connected to the        first and second chambers to fluidly connect the first chamber        to the second chamber, wherein the outlet is arranged in fluid        communication with the conduit.

The drain apparatus may further comprise:

-   -   at least one valve arranged in the conduit for controlling a        flow through the conduit.

The liquid extraction means may comprise a reservoir in fluidcommunication with an opening formed in the bottom of the chamber. Theopening may have a diameter substantially equal to the diameter of thechamber. The opening may extend across the full width of the chamber.The reservoir may comprise an overflow outlet formed through a sidesurface of the reservoir for transporting gas to the chamber.

The outlet may be formed through the bottom of the chamber. The outletmay extend into the chamber and may be formed through an upper surfaceof the chamber. The outlet may be formed through the bottom of thereservoir. The outlet may extend into the reservoir and may be formedthrough an upper surface of the chamber.

The outlet may be in fluid communication with a third channel. The thirdchannel may be an internal conduit of a subsea umbilical line or asecond subsea pipe.

The drain apparatus may further comprise at least one pump coupled tothe outlet and configured to receive liquid from the outlet and pump theliquid to the surface.

The chamber or the reservoir may further comprise a control mechanismconfigured to activate the at least one pump when a liquid level in thechamber or the reservoir exceeds a threshold.

The liquid extraction means may comprise: a first liquid extractionchamber comprising at least one first inlet to receive liquid from thefirst channel; a second liquid extraction chamber comprising at leastone second inlet to receive liquid from the first channel, wherein thefirst channel is arranged to pass through the first liquid extractionchamber before the second liquid extraction chamber; a first storagetank arranged to receive liquid from the first liquid extractionchamber; and a second storage tank arranged to receive liquid from thesecond liquid extraction chamber. Additionally, the drain apparatus mayfurther comprise a first gas conduit connecting the first storage tankto the first channel to permit gas flow between the first storage tankand the first channel, and/or a second gas conduit connecting the secondstorage tank to the first channel to permit gas flow between the secondstorage tank and the first channel. In some embodiments the first gasconduit and the second gas conduit are connected to the first channelafter the second liquid extraction chamber. In other embodiments thefirst gas conduit is connected to the first channel before the secondliquid extraction chamber, and the second gas conduit is connected tothe first channel after the second liquid extraction chamber.Furthermore, in some embodiments the first channel is configured suchthat when the drain apparatus is installed in the subsea pipeline thefirst and second liquid extraction chambers are raised above a level ofthe subsea pipe at either end of the first channel, such that the firstand second storage tanks can be located at or above the level of thesubsea pipe and below a level at which the first and second liquidextraction chambers are located. The first channel may be weldeddirectly to the subsea pipe.

The drain apparatus may further comprise at least one injection port forinjecting a hydrate inhibitor into the first channel. The injection portmay extend through an outer surface of the first channel where the firstchannel protrudes from the dry side of the chamber. The injection portmay comprise at least one valve for controlling the rate of flow ofhydrate inhibitor into the first channel. The at least one injectionport may be arranged to receive hydrate inhibitor from a fourth channel.The fourth channel may be an internal conduit of a subsea umbilical lineor a third subsea pipe.

The hydrate inhibitor may be at least one of Ethylene glycol [MEG],Methanol or a low dose hydrate inhibition chemical.

According to a second aspect of the present invention, there is provideda subsea pipeline comprising:

-   -   a subsea pipe for transporting a multiphase flow subsea; and    -   at least one drain, wherein the at least one drain is disposed        partway along a gradient in the subsea pipe to reduce liquid        holdup.

Advantageously, the second aspect allows gas to be transported greaterdistances by reducing pressure losses through the gravitational effectof liquid in the multiphase flow, as it has been shown that positioninga drain along a gradient rather than at the bottom of the gradient drawsout more liquid from the subsea pipe.

The at least one drain may be disposed at a point along the gradient atwhich liquid holdup in the subsea pipeline would otherwise causeslugging to occur. That is to say, the position of the at least onedrain can be determined according to the liquid holdup in relation tothe gradient that causes a slugging regime.

The at least one drain may be disposed about 15% of the way along thelength of the gradient when measured from the lowest point of thegradient.

The at least one drain may comprise the drain apparatus according to thefirst aspect, wherein the ends of the first channel may be fluidlycoupled inline with the subsea pipe. The ends of the first channel maybe welded to the subsea pipe.

The subsea pipeline may comprise a plurality of drain apparatuses,wherein an inlet of each pump is arranged to receive liquid from a pumpof another drain apparatus.

The subsea pipeline may further comprise a subsea umbilical line havingat least one internal conduit coupled to an outlet of the drain andconfigured to receive liquid from the outlet and transport it to thesurface or an offshore terminal, and/or at least one internal conduitcoupled to an injection port of the drain and configured to deliverhydrate inhibitor from the surface or an offshore terminal to theinjection port. The hydrate inhibitor is at least one of Ethylene glycol[MEG], Methanol or a low dose hydrate inhibition chemical.

All features described herein (including any accompanying claims,abstract and drawings), and/or all of the steps of any method or processso disclosed, may be combined with any of the above aspects in anycombination, except combinations where at least some of such featuresand/or steps are mutually exclusive.

BRIEF DESCRIPTION OF THE FIGURES

Embodiments of the present invention will now be described, by way ofexample only, with reference to the accompanying drawings, in which:

FIG. 1 shows a subsea drain according to one embodiment of the presentinvention;

FIGS. 2 a, 2 b and 2 c show a subsea drain apparatus according to anembodiment of the present invention;

FIGS. 3 a and 3 b show a subsea drain apparatus according to anotherembodiment of the present invention;

FIG. 4 shows a subsea drain apparatus according to another embodiment ofthe present invention;

FIG. 5 shows a subsea drain apparatus according to another embodiment ofthe present invention;

FIG. 6 shows a subsea drain apparatus according to another embodiment ofthe present invention;

FIG. 7 shows a subsea pipeline having a subsea drain apparatus accordingto an embodiment of the present invention;

FIG. 8 shows a subsea drain apparatus according to an embodiment of thepresent invention;

FIG. 9 shows a subsea drain apparatus according to an embodiment of thepresent invention;

FIG. 10 shows a subsea drain apparatus according to an embodiment of thepresent invention;

FIGS. 11 a and 11 b show a subsea drain apparatus according to anembodiment of the present invention;

FIG. 12 shows a subsea pipeline having a subsea drain apparatusaccording to an embodiment of the present invention;

FIG. 13 shows a subsea pipeline having a subsea drain apparatusaccording to an embodiment of the present invention;

FIG. 14 shows a subsea pipeline having a drain apparatus according to anembodiment of the present invention;

FIG. 15 shows a subsea umbilical line;

FIG. 16 shows a gathering system having a drain apparatus according toan embodiment of the present invention;

FIG. 17 is a graph showing the improved efficiency of the pipeline inFIG. 15 over prior art pipelines;

FIG. 18 is a graph showing the effect of distance from a well head onliquid drop out rate;

FIG. 19 is a graph showing the flow regimes that occur within a subseapipe;

FIG. 20 illustrates a pig passing through a drain apparatus for removingliquid from a multiphase flow in a subsea pipeline, according to anembodiment of the present invention;

FIG. 21 illustrates a drain apparatus in perspective view, according toan embodiment of the present invention;

FIG. 22 illustrates a side elevation view of the drain apparatus of FIG.21 ;

FIG. 23 illustrates a cross-sectional view of the drain apparatus ofFIG. 21 ;

FIG. 24 illustrates a drain apparatus in perspective view, according toan embodiment of the present invention;

FIG. 25 illustrates a side elevation view of the drain apparatus of FIG.24 ; and

FIG. 26 illustrates a cross-sectional view of the drain apparatus ofFIG. 24 .

DETAILED DESCRIPTION

As noted above, a first aspect of the present invention provides a drainapparatus for use in a subsea pipeline. It would be generally understoodthat drains, pipes and other components designed for the subseaenvironment need to remain in place for many years while withstandingchallenging conditions. For example, equipment for use in a subseaenvironment should be corrosion-resistant, and be able to withstand highpressures. By way of example, the drain apparatuses described herein canbe made of a suitable material for use in subsea environments, such ashigh density polyethylene (HDPE), carbon steel or corrosion-resistantalloys. Furthermore, as the bottom of the sea is relativelyinaccessible, system redundancy is highly desirable.

Another design consideration when working subsea is the necessity toperform pigging operations without being able to remove a pig to bypassa vessel too small for the pig to pass through. A pig could be, forexample, a cleaning pig (operational pigging), or a leak detection pig(inspection pigging). As shown in FIG. 20 , a pig 800 comprises at leasttwo driving seals 801, 802, commonly referred to as cups, connectedtogether by a mandrel 803. The length of the mandrel is normally between0.8 and 1.5 times the internal diameter of the subsea pipeline. The pig800 can be driven through the subsea pipeline by way of a pressuredifferential across the pig 800. The pressure differential may begenerated by the natural pressure of the wells, for example as is thecase during operational pigging, or may be generated by alternativemeans, such as a pump.

The length of the mandrel 803 that is compatible with a given pipelinesystem is influenced by two parameters: firstly, the size of any barredtees within the system; and secondly, the minimum radius of any bendswithin the system. The size of any barred tees determines the minimumlength of the mandrel 803, such that it does not get stuck at a barredtee due to fluids/gases being able to flow around the pig 800. Theminimum bend radius within a pipeline system determines the maximumlength of the mandrel 803, as the pig will need to be able to pass roundbends. Pipeline systems are commonly designed to have a minimum bendradius of 3 to 5 times the diameter of the pipeline, in order toaccommodate pigging operations. If the mandrel 803 is too long, or ifthe minimum bend radius is too small, the pig 800 will become physicallystuck at the bends with significant impacts to both production flowratesand future inspectability of the pipeline system. It has been known tojoin a number of pigs together with a tether, for example duringinspection pigging, but this brings additional complications and risksof failure during a pigging run.

On land, it is possible to position pig receiving stations and piglaunching stations wherever necessary to service the whole gatheringpipeline network. A pig launching station may also be referred to as a‘pig launcher’, and a pig receiving station may also be referred to as a‘pig catcher’. Subsea, however, pig launchers and receivers are onlyprovided at the well heads, major nodal points on gathering systems, orterminals of subsea pipelines, due to the high cost and complexityassociated with inserting and removing pigs in a subsea environment.

Throughout this document, the term “subsea pipe” is used to refer to thepipe that carries the multiphase flow. The subsea pipe may also bereferred to as a “carrier pipe”, since the function of the subsea pipeis to carry production gas away from the well head. The term “subseapipeline” is used to refer to a system comprising at least the subseapipe and a liquid extraction means such as a subsea drain. The terms“gathering system” and “gathering network” are used to refer to a systemcomprising at least one subsea pipeline (where one subsea pipeline maybranch off another subsea pipeline), at least one well head and at leastone processing facility.

A subsea drain is designed to remove liquids from a multiphase flowbeing transported in a pipe of a subsea pipeline. Liquid in the subseapipeline will reduce pressure and consequently the distance that gas inthe multiphase flow can be transported. The multiphase flow, forexample, is production gas. The liquid in the multiphase flow isprimarily water and hydrocarbons. Contaminants, such as fine sedimentarydeposits or liquid chemicals, might also be present in the multiphaseflow. The liquid naturally separates from the gas in the multiphase flowdue to variations in the pressure caused by frictional means andtopography of the ground, and the change in temperatures due to thedelta between the gas and the ambient water temperature.

One example of a subsea drain 100 according to an embodiment of thepresent invention is shown in FIG. 1 . As shown in FIG. 1 , the body ofthe subsea drain 100 constitutes a chamber 12 for receiving multiphaseflow from an inlet 10. Liquid, which sinks to the bottom of the chamber12, drains out of a liquid outlet 14 fluidly coupled to the bottom ofthe chamber 12. The inlet 10 preferably curves downwards as shown inFIG. 1 , so that the multiphase flow will be directed towards the bottomof the chamber 12. This arrangement can prevent the multiphase flow fromsimply bypassing the liquid outlet 14 at high flow rates. Furtherdesigns for the liquid outlet 14 are described with reference to FIGS. 3a and 3 b that follow. The chamber 12 also has a gas outlet 15 formed onthe opposite side to the side having the inlet 10. It would also beapparent to the skilled person that the gas outlet 15 could be formed ona side of the chamber 12 perpendicular to the side having the inlet 10.As the gas rises above the liquid, positioning the gas outlet 15 higherthan the lowest point of the chamber 15 reduces the likelihood of liquidcontinuing to flow with the gas out of the drain 100.

FIG. 1 shows an idealised system, where liquid mixed with gas entersthrough the inlet 10, and only gas leaves the drain 100 through the gasoutlet 15. It would be apparent to the skilled person that the substanceleaving the gas outlet 15 is likely to remain a multiphase flow, ratherthan be pure gas, and so further drains 100 will be necessary to removeliquid that later precipitates out of the multiphase flow. However, forclarity, the side of the drain 100 having the inlet 10 is referred to asthe wet side and the side having the gas outlet 15 is referred to as thedry side. Less liquid will leave the dry side than the amount of liquidthat entered the wet side. The same reasoning applies to later-describedembodiments.

In general the chamber 12 may have any suitable shape. For example, thechamber 12 may be cuboidal, as shown in FIG. 1 , or may be cylindricalas shown in later Figures.

As the gas outlet 15 is curved, and the gas outlet 15 is detached fromthe inlet 10, it would be impossible for a pig to pass through thesubsea drain of FIG. 1 . It is essential for pigging operations to beperformed in most jurisdictions. However, it is not possible to remove apig and reinsert it into a pipe in a subsea environment without asubstantial increase in the number of subsea structures and overallincrease in capital expenditure (CAPEX) and operational expenses (OPEX).Therefore, the present invention also provides a means for a pig tobypass the subsea drain 100 shown in FIG. 1 or any other design ofliquid drain. Throughout this document, bypass means combined with adrain constitute a drain apparatus. In some embodiments, described withreference to FIGS. 2 a to 6 later, these bypass means are arranged onthe longitudinal axis of the drain. In other embodiments, described withreference to FIGS. 8 to 11 b later, these bypass means are offset fromthe longitudinal axis of drain (or, in other words, arranged outside ofthe drain).

In the embodiment shown in FIG. 1 , a subsea pipe acts as the separatorfor separating liquid from the multiphase flow, while the drain 100simply extracts the liquid.

In operation, the chamber 12 is configured to be free of standingliquids.

FIGS. 2 a and 2 b show a subsea drain apparatus 200 according to anembodiment of the present invention. The drain apparatus 200 includes achannel 20 for carrying a multiphase flow that passes through the drainapparatus 200. The drain apparatus 200 further comprises a chamber 12for receiving liquid from the channel 20, and a liquid outlet 14 forreceiving liquid from the chamber 12. The drain apparatus 200 isdesigned to be a standalone structure that can be installed into apipeline as a single unit.

More specifically, FIG. 2 a shows a view through the longitudinal axisof the drain apparatus 200. The channel 20 passes continuously through acylindrical chamber 12. In other words, the cylindrical chamber 12 has agreater diameter than the diameter of the channel 20. The channel 20 hasa diameter approximately equal to the diameter of a subsea pipe fortransporting a multiphase flow, to which the drain apparatus 200 will becoupled. The drain apparatus 200 is configured to be installed inlinewith a subsea pipe with a certain internal diameter, by connecting openends of the subsea pipe to the open ends of the channel 20.Additionally, the channel 20 has a diameter that is substantially thesame as the internal diameter of the subsea pipe, such that a pig cantravel through the channel 20 and the subsea pipe. As a result, when thedrain apparatus 200 is installed inline with the subsea pipe, a pigtravelling along the subsea pipe can pass through the drain apparatus200 via the channel 20 and continue unhindered (or continuously, oruninterrupted) along the subsea pipe.

The channel 20 has a circular cross section inside the chamber 12 suchthat the channel 20 forms a tube running through the chamber 12.Alternatively, inside the chamber 12, the channel 20 may have asemi-circular cross section such that the top of the chamber 12 forms abarrier between the channel 20 and the sea. In all embodiments, wherethe channel 20 extends outside of the chamber 12, the channel 20 is inthe form of a tube so that the multiphase flow is not in fluidcommunication with the sea.

The chamber 12 may have a rectangular cross section instead of thecircular cross section shown in FIG. 2 a . FIG. 2 a further shows areservoir 16 extending from the bottom of the chamber 12. The reservoir16 receives liquid from the chamber 12 through an opening 18 in thechamber 12. In an exemplary embodiment, the opening 18 is formed in thebottom of the chamber 12. In other embodiments, the opening 18 is formedin the wall of the chamber at a point lower than the lowest one of aplurality of inlets 11 (or lower than the inlet 11 where there is onlyone inlet 11), such that standing liquid does not form in the channel20. The opening 18 has a diameter approximately equal to the diameter ofthe chamber 12. In this configuration, the walls of the reservoir 16couple to the chamber 12 at the widest point of the chamber 12. Thechamber 12 and the reservoir 16 are integrally formed, i.e. in onepiece. Alternatively, the reservoir 16 and the chamber 12 may befabricated as separate components that are then welded together.Advantageously, the reservoir 16 improves the liquid extractionefficiency of the drain apparatus 200 as more liquid is able to fall outof the chamber 12, and consequently the channel 20, per second.

In the embodiments of the present invention described herein, the drainis configured to remove the liquid phase from the multiphase flow suchthat the channel 20 is arranged to be free of standing liquid. Thereservoir 16 assists in draining the channel 20 so that it isessentially dry during operation, but is not essential unless there isexcessive liquid being carried in the multiphase flow. The lack ofstanding liquid creates a less corrosive environment for the channel 20,which improves the reliability of the system. There are additionalbenefits, such as when pigging, a liquid slug does not form in front ofthe pig to allow smoother operations. Also, by having an excessiveamount of liquid in front a pig, production may have to be stoppedprematurely due to a reduction in system pressure.

A liquid outlet 14 is formed in fluid communication with the bottom ofthe reservoir 16. In other words, the liquid outlet 14 communicates withthe reservoir 16 through an opening in the bottom of the reservoir 16.The liquid outlet 14 has an internal diameter less than that ofreservoir 16. The reservoir 16 shown in FIG. 2 a has a flat bottomsurface. Alternatively, the bottom surface of the reservoir 16 may tapersuch that liquid is funneled into the liquid outlet 14.

Alternatively, the liquid outlet 14 may be formed to pass through a sidewall of the reservoir 16, and arranged such that liquid can drain out ofthe reservoir 16 without inhibiting the multiphase flow in the channel20.

The reservoir 16 includes a liquid level sensor 22 on its internalsurface. The liquid level sensor 22 is for example an optical sensor andlight emitter. The light emitter transmits a light beam across thereservoir 16, which is reflected off the opposite wall of the reservoir16 and received at the optical sensor. The intensity of the reflectedlight will reduce when a liquid level rises over the level of the liquidlevel sensor 22. This is just one example of a liquid level sensor 22,and the skilled person would appreciate there are many otheralternatives, such as using a float.

The liquid level sensor 22 is electrically coupled to a pump, which isdescribed later. When the liquid level in the reservoir exceeds athreshold level, the pump, in fluid communication with the outlet 14, isactivated to remove liquid from the drain apparatus 200 faster.

Alternatively to the design shown in FIG. 2 a , the liquid outlet 14 maybe coupled directly to the bottom of the chamber 12 such that there isno reservoir 16 between the liquid outlet 14 and the chamber 12. This isshown in FIG. 2 c . In embodiments where the liquid outlet 14 is coupleddirectly to the chamber 12, the liquid level sensor 22 is disposed inthe liquid outlet 14.

FIG. 2 b shows a perspective view of the subsea drain apparatus 200 ofFIG. 2 a . Here, it is clear that in the present embodiment some of thechannel 20 protrudes from both ends of the chamber 12. In otherembodiments, the channel 20 could be the same length as the chamber 12such that the subsea pipeline can be directly coupled to openings in theend walls of the chamber 12. The chamber 12 is closed at both endsexcept where the channel 20 protrudes, such that liquid entering thechamber 12 is contained within the chamber 12 until extracted via theliquid outlet 14. The channel 20 may be welded into the ends of thechamber 12 or may be joined to the chamber 12 using a suitablemechanical connection. Alternatively, the chamber 12 and channel 20 maybe integrally formed.

The channel 20 includes at least one inlet 11 in fluid communicationwith the chamber 12. The inlet 11 is sized so that it does not affectthe passage of a pig. In other words, the length of the inlet 11 is lessthan the length of a pig. Where there is more than one inlet 11, theymay be formed along the longitudinal axis of the channel 20, or aroundthe circumference of the channel 20, or both. The inlets 11 aretypically formed towards the bottom of the channel 20 so that liquid,heavier than the production gas, can drain out. However, as shown inFIG. 19 , various flow regimes can occur within a subsea pipe. FIG. 19is for a subsea pipe at 0 degree inclination. Slugging may occur, forexample, at a superficial liquid velocity of between about 0.1 m/s and 5m/s and a superficial gas velocity of between 1 m/s and 100 m/s. Underthese operating conditions gas and liquid are not evenly distributedthroughout the subsea pipe, but travel as large plugs with mostlyliquids or mostly gases through the subsea pipe. These large plugs canbe referred to as ‘slugs’. Annular flow is where liquid forms around theinside wall of a subsea pipe, but the production gas travels down thecentre of the pipe. Therefore, it is preferential to install inlets 11at several different points on the surface of the channel 20.

FIGS. 3 a and 3 b show a subsea drain apparatus 300 having a similararrangement to the subsea drain apparatus 200 described with referenceto FIGS. 2 a and 2 b . Description of the same features will not berepeated.

The subsea drain apparatus 300 includes a liquid outlet 14 that extendsfrom the reservoir 16 to, and out of, the upper outer surface of thechamber 12. The liquid outlet 14 may exit the chamber 12 through anupper side portion of the chamber 12, or through the top of the chamber12.

The bottom of the liquid outlet 14 is spaced apart from the bottom ofthe reservoir 16 such that liquid can be drawn into the liquid outlet14. This is clear from FIG. 3 a . Alternatively, the bottom of theliquid outlet 14 may contact the bottom of the reservoir 16, but here atleast one opening is disposed in a wall of the liquid outlet 14 at alower portion of the liquid outlet 14 so that liquid can be drawn intothe liquid outlet 14 from the reservoir 16.

As shown in FIG. 3 a , the liquid outlet 14 passes through both thechamber 12 and the channel 20. FIG. 3 a is not drawn to scale, and itwould be apparent that the diameter of the liquid outlet 14 is narrowrelative to the diameter of the channel 20 and the liquid outlet 14 isoffset from the central region of the channel 20, such that it does notinhibit pigging operations through the channel 20.

Alternatively, the liquid outlet 14 is a curved pipe that passes aroundthe outside of the channel 20. In other words, the liquid outlet 14 iscurved to follow the contour of the chamber 12 and/or the contour of theoutside of the channel 20, and does not pass directly through thechannel 20.

It would also be apparent that the design of liquid outlet 14 describedwith reference to FIGS. 3 a and 3 b could be implemented in the drain100 shown in FIG. 1 , where the diameter of the liquid outlet 14 neednot be relatively small as pigs do not pass through the chamber 12 ofthe drain 100 anyway.

Having the liquid outlet 14 extend from the top of the chamber 12reduces the extent to which the structure must be designed toaccommodate the seabed with regards to the drain apparatus 300.Penetrating deep into the seabed is a difficult and expensive process.

Similarly to as described with reference to FIG. 2 c , the liquid outlet14 may extend from the chamber 12 instead of a reservoir 16.

FIG. 4 shows a perspective view of a drain apparatus 400 according toanother embodiment of the present invention. The features of FIG. 4 thatare common to FIGS. 2 a and 2 b will not be described repeatedly.

It is known to inject hydrate inhibitor, typically Ethylene glycol(MEG), into a multiphase flow to suppress the formation of hydrateswhich could otherwise restrict flow along the pipeline and causeoperational issues. The hydrate inhibitor is typically injected into thepipeline close to or at the well head. Therefore, as liquid is lost fromthe pipeline through known subsea drains, the hydrate inhibitor is alsolost from the system. Consequently, greater quantities of hydrateinhibitor need to be injected than are actually required. The presentinvention solves this problem by injecting hydrate inhibitor into thechannel 20 transporting the multiphase flow after the liquid thatprecipitated out of the multiphase flow has escaped through each liquidoutlet 14. In other words, hydrate inhibitor is injected into themultiphase flow on the dry side of the drain apparatus 400 through aninjection port 24 (or vessel, or duct) in fluid communication with thechannel 20. By injecting hydrate inhibitor at regular intervals, theamount of hydrate inhibitor needed is reduced.

The injection port 24 penetrates the channel 20. The injection port 24may be a flexible conduit, or a rigid pipe. The injection port 24 ismade of any suitable subsea material, such as carbon steel. Theinjection port 24 is welded to the channel 20 at a positioncorresponding to an opening in the outer surface of the channel 20.

At the other end of the injection port 24, the injection port 24 iscoupled to a hydrate inhibitor injection line 26. The hydrate inhibitorinjection line 26 is a subsea pipe for transporting hydrate inhibitor toall drain apparatuses 400 disposed along the subsea pipeline.

At least one valve 25 is disposed in the injection port 24. The at leastone valve 25 controls the rate of flow of hydrate inhibitor into themultiphase flow. In this way, more hydrate inhibitor can be injectedinto a drain apparatus 400 close to the well head, where a greaterquantity of liquid will remain in the multiphase flow after the drainapparatus 400, than a drain apparatus 400 close to the processingfacility on the land.

In some embodiments, instead of being a dedicated subsea pipe, thehydrate inhibitor injection line 26 is at least one internal conduit ofa subsea umbilical line 46, as described with reference to FIG. 15 .

While FIG. 4 shows a drain apparatus 400 having the features of thedrain apparatus 200 shown in FIGS. 2 a and 2 b , it would be readilyapparent that the concept of the hydrate inhibitor injection port 24 canbe applied to the drain 100 of FIG. 1 , where the hydrate inhibitor isinjected into the gas outlet 15, the drain apparatus 200 of FIG. 2 c ,the drain apparatus 300 of FIGS. 3 a and 3 b , or any later-describeddrain apparatuses.

FIG. 5 shows a perspective view of a subsea drain apparatus 500according to another embodiment of the present invention. The subseadrain apparatus 500 of FIG. 5 is substantially the same as the subseadrain apparatus 200 of FIGS. 2 a and 2 b , and description of identicalfeatures will not be repeated.

Additionally to the subsea drain apparatus 200 described previously, thedrain apparatus 500 of FIG. 5 includes an overflow outlet 28 fluidlycoupling the reservoir 16 to the dry side of the chamber 12. Theoverflow outlet 28 penetrates the chamber 12 and the channel 20 suchthat production gas that inadvertently leaked through the opening 18 inthe chamber 12 can be reinjected into the multiphase flow in the channel20. Alternatively to the embodiment shown in FIG. 5 , the overflowoutlet 28 may reinject production gas into the channel 20 outside of thechamber 12 on the dry side of the drain apparatus 500.

Further to these advantages, the overflow outlet 28 creates a secondarygas flow and centrifugal forces to pull the liquids into the reservoir16, thus increasing efficiency.

The overflow outlet 28 is arranged in the side of the reservoir 16,preferably between the liquid level sensor 22 and the opening 18.

As production gas is lighter than liquid, the liquid outlet 14 will besubstantially blocked by the liquid, such that the production gas thatescaped into the reservoir 16 is more likely to enter the overflowoutlet 28 than the liquid outlet 14.

Additionally, any liquid that avoided falling through the opening 18 andentered the dry side of the drain apparatus 500 is captured by theoverflow outlet 28, which transports the liquid back to the reservoir16.

The overflow outlet 28 may also be arranged at an acute angle relativeto the horizontal plane, to prevent the likelihood of liquid rising backup to the dry side of the drain apparatus 500 through the overflowoutlet 28, and to draw any liquid in the overflow outlet back to thereservoir 16.

The subsea drain apparatus 500 includes a liquid outlet 14 extendingfrom the bottom surface of the reservoir 16. However, the concept of theoverflow outlet 28 can also be applied to embodiments having the liquidoutlet 14 arranged as described with reference to FIGS. 2 c, 3 a and 3 b, the drain 100 without a reservoir 16 as described with reference toFIG. 1 , and the hydrate inhibitor injection port 24 described withreference to FIG. 4 .

FIG. 6 shows a subsea drain apparatus 550 according to anotherembodiment. Here, the chamber 12 is divided into a first chamber 12 aand a second chamber 12 b by a baffle 13. The baffle 13 is an annularstructure through which the channel 20 passes.

At least one first inlet 11 a is disposed on the dry side of the chamber12. In other words, the at least one first inlet 11 a is disposed in thefirst chamber 12 a. At least one second inlet 11 b is disposed on thewet side of the chamber 12. In other words, the at least one secondinlet 11 b is disposed in the second chamber 12 b. The first inlets 11 aand second inlets 11 b are of a length less than the length of a pig.

The arrangement of the baffle 13 and first and second inlets 11 a, 11 binduces a pressure differential across the chamber 12.

A first opening 18 a is formed in the wall of the first chamber 12 a ata point lower than the lowest of the first inlets 11 a. Preferably, thefirst opening 18 a is formed in the bottom of the first chamber 12 a. Asecond opening 18 b is formed in the wall of the second chamber 12 b ata point lower than the lowest of the second inlets 11 b. Preferably, thesecond opening 18 b is formed in the bottom of the second chamber 12 b.

The first and second openings 18 a, 18 b are fluidly coupled by aconduit 19. The conduit 19 is disposed outside of the chamber 12. Theliquid outlet 14 is fluidly coupled to the conduit 19. In an exemplaryembodiment, the liquid outlet 14 is fluidly coupled to the lowest pointin the conduit 19. In another embodiment, a portion of the conduit 19can be enlarged at act as the liquid reservoir 16 according topreviously described embodiments. In some embodiments, the portion isthe bottom section of the conduit 19.

The pressure differential between the first chamber 12 a and the secondchamber 12 b draws liquid out of the channel 20 and into the conduit 19,such that the conduit 19 provides a secondary gas flow. The liquid thendrains through the liquid outlet 14 in the bottom of the conduit 19.

Although not essential to the inventive concept, at least one valve 17a, 17 b can be disposed in the conduit. In the present embodiment, afirst valve 17 a is disposed at the end of the conduit 19 closest to thefirst opening 18 a, and a second valve 17 b is disposed at the end ofthe conduit 19 closest to the second opening 18 b. The valves 17 a, 17 bare closed during pigging operations to improve the efficiency of pigtransport.

FIG. 7 shows a subsea pipeline 600 according to an embodiment of thepresent invention. Here, a drain apparatus 200 according to FIGS. 2 aand 2 b is integrated with a subsea pipe 30. The open longitudinal endsof the channel 20 are coupled to open ends of a subsea pipe 30. The endsof the channel 20 are coupled to the ends of the subsea pipe 30 bywelding. In FIG. 7 , the channel 20 and subsea pipe 30 are welded atweld points 32. Alternatively, the ends of the subsea pipe 30 and theends of the channel 20 may include perpendicular flanges, which can bealigned and bolted or riveted with each other, or mechanical connectionsystems known for subsea systems. A gasket or seal may also be disposedbetween the ends of the subsea pipe 30 and the channel 20 to furtherprevent the multiphase flow from escaping the subsea pipeline 600.

As with the embodiment shown in FIGS. 2 a and 2 b , in the presentembodiment the internal diameter of the channel 20 and the internaldiameter of the subsea pipe 30 are approximately equal. Therefore, apig, such as a pipe inspection pig, is able to travel through both thechannel 20 and the subsea pipe 30 uninterrupted.

The subsea pipeline 600 includes a pump 42 coupled to the liquid outlet14. The pump 42 according to this embodiment forms part of the drainapparatus 200 prior to installation of the drain apparatus 200 on theseabed. In other words, the pump 42 becomes integrated with the subseapipeline 600 upon the ends of the channel 20 being coupled to the subseapipe 30. Alternatively, the pump 42 can be installed on a retrievablesubstructure within the drain apparatus 200. Alternatively, the pump 42may be pre-installed on the seabed, and the liquid outlet 14 is coupledto the pump 42 after the drain apparatus 200 has been laid.

The pump 42 may be continually active to draw liquid from the drainapparatus 200. Alternatively, the pump 42 may be activated by the liquidlevel sensor 22 detecting that level of liquid in reservoir 16 (orliquid outlet 14) exceeds a threshold.

At one inlet of the pump 42, the pump 42 is coupled to the liquid outlet14 of the drain apparatus 200. At another inlet of the pump 42, the pump42 is coupled to a liquid removal line 44 coupled at its other end toanother pump. The pumps 42 work in unison to effectively draw liquidfrom plural drain apparatuses. In other words, each drain apparatus 200acts as a pumping station for moving liquid to the next drain apparatusin the system. Using a plurality of pumps 42 disposed along the pipeline600 reduces the pumping overhead versus the prior art, where a single ora plurality of pumps are installed at the end of the pipeline.Furthermore, system redundancy is improved, which is particularimportant in inaccessible subsea environments. An outlet of the pump 42is coupled to a liquid removal line 44 for transporting the extractedliquid to a processing facility on the land or an offshore terminal.

The liquid removal line 44 shown in FIG. 7 is a separate subsea pipe.However, in other embodiments, the liquid removal line 44 is an internalconduit of a subsea umbilical line 46.

Rather than there being a pump 42 disposed between separate liquidremoval lines 44, the pump 42 may be disposed within a single liquidremoval line 44.

While FIG. 7 has been described with reference to the subsea drainapparatus 200 of FIGS. 2 a and 2 b , in other embodiments the subseapipeline 600 includes any of the subsea drain apparatuses described withreference to FIGS. 2 c to 6.

FIG. 8 shows a plan view of a subsea drain apparatus 700 according toanother embodiment. In other words, FIG. 8 is shown from the perspectiveof someone looking down onto the drain apparatus 700 which is sitting,for example, on the seabed. Here, a drain 100 as shown in FIG. 1 isoffset from, and coupled to, a bypass channel 21 by the inlet 10 and thegas outlet 15. Alternatively to the drain 100 according to FIG. 1 , thedrain apparatus may include a separator or slug catcher. A slug catcheris a term of art, and will not be described in detail here. In theembodiment shown in FIG. 8 , a subsea pipe 30 with which the drainapparatus 700 is integrated acts as the separator for separating liquidfrom the multiphase flow, while the drain 100 simply extracts theliquid. The drain apparatus 700 is designed to be a standalone structurethat can be installed into a pipeline as a single unit or as a separatemanifold connected by spools.

As part of a subsea pipeline, the bypass channel 21 is coupled to asubsea pipe 30 in the manner explained with reference to FIG. 7 . Inother words, the drain 100 is offset from the bypass channel 21 and thesubsea pipe 30 in the horizontal plane. The drain 100 may be furtheroffset from the bypass channel 21 and the subsea pipe 30 in the verticalplane. Moreover, the internal diameter of the bypass channel 21 issubstantially the same as that as the subsea pipe 30, so that a pig cantravel through the bypass channel 21 and the subsea pipeline 30uninterrupted.

A valve 34 a is disposed in the inlet 10 and a valve 34 b is disposed inthe bypass channel 21 in order to control the direction of travel ofmultiphase flow or a device travelling through the subsea drainapparatus 700. To prevent disruption to the flow, or damage to the pigor drain apparatus 700, the valves 34 a, 34 b are disposed as close tothe junction between the inlet 10 and bypass channel 21 as possible.

When the valve 34 a in the inlet 10 is closed and the valve 34 b in thebypass channel 21 is open, a pig is able to travel from a well head,through the bypass channel 21, towards land, without becoming stuck inthe drain 100. Conversely, when the valve 34 a in the inlet 10 is openand the valve 34 b in the bypass channel 21 is closed, the multiphaseflow is able to pass through the drain 100 so that liquid in themultiphase flow is drawn out of the multiphase flow.

While FIG. 8 shows the liquid outlet 14 pointing towards the bypasschannel 21, in other embodiments, the liquid outlet 14 is arranged toface directly away from the bypass channel 21, or upwards and directlyaway from the seabed. When the drain 100 is offset from the bypasschannel 21 in the vertical plane, the liquid outlet 14 may be arrangedto point vertically downwards, as the offset raises the drain 100 fromthe seabed and prevents subsea excavation work being necessary to burythe liquid removal line 44 that will be connected to the liquid outlet14 when the drain apparatus 700 is integrated with a subsea pipe 30 toform a subsea pipeline.

In embodiments of the present invention, by configuring the apparatus soas to support the drain 100 at a certain height above the seabed, aliquid storage vessel for collecting and storing liquid extracted viathe liquid outlet 14 can also be situated above the seabed, therebyremoving the need to excavate the seabed in order to accommodate theliquid storage vessel. For example, a liquid storage vessel may comprisea reservoir 16 or conduit 19 disposed beneath the drain 100, asdescribed above with reference to FIGS. 4, 5 and 6 , or may comprise aseparate vessel situated a certain distance away from the drain andconnected to the liquid outlet 14 formed in the drain 100 via a suitableconnection, such as a pipe arranged to carry liquid from the liquidoutlet 14 to the storage vessel.

In embodiments in which the drain 100 is raised above the seabed, thedrain 100 may consequently be situated above the level of the mainpipeline, which typically rests directly on the seabed. A difference inheight between the drain 100 and the pipeline can be accommodated invarious ways, for example, through natural elastic deflection within thepipeline either side of the drain 100, or by providing a prefabricatedpiggable bend before and/or after the drain 100, to connect the raiseddrain 100 to the pipeline at a lower level.

FIG. 9 shows a plan view of a subsea drain apparatus 800 according toanother embodiment. The subsea drain apparatus 800 is similar to thesubsea drain apparatus 700 described with reference to FIG. 8 . In FIG.9 , a valve 34 c is disposed in the gas outlet 15. A further valve 34 dis disposed in the bypass channel 21. To prevent disruption of the flowor damage to the pig or drain apparatus 800, the valves 34 c, 34 d aredisposed as close to the junction between the gas outlet 15 and thebypass channel 21 as possible.

The additional valves 34 c, 34 d allow pigging operations to beperformed in both directions along the subsea pipeline, i.e. from wellhead to land (or an offshore facility) and from land (or an offshorefacility) to well head. Additionally, the additional valves 34 c, 34 dprovide more control over the drain apparatus 800. Additionally, theadditional valves 34 c, 34 d prevent multiphase flow that passed throughthe drain 100 from returning back down the bypass channel 21, andprevent a pig that bypassed the drain 100 through the bypass channel 21from entering the gas outlet 15.

FIG. 10 shows a plan view of a subsea drain apparatus 900 according toanother embodiment. The drain apparatus 900 includes a drain 100 andvalves 34 a-d as described with reference to FIG. 9 . Alternatively to adrain 100, the drain apparatus 900 may include a separator or slugcatcher.

Further to the subsea drain apparatus 800 of FIG. 9 , the drainapparatus 900 of FIG. 10 includes an inline tee junction 36 at thejunction between the bypass channel 21 and the inlet 10 and at thejunction between the bypass channel 21 and the gas outlet 15.

The inline tee junction 36 is welded into the bypass channel 21 andinlet 10, and into the bypass channel 21 and gas outlet 15.

The use of inline tee junctions 36 improves manufacturing efficiency andimproves the reliability of the subsea drain apparatus 900.

FIGS. 11 a and 11 b show a plan view of a subsea drain apparatus 1000according to another embodiment. FIG. 11 a shows the subsea drainapparatus 1000 operating in a first mode of operation. FIG. 11 b showsthe subsea drain apparatus 1000 operating in a second mode of operation.The subsea drain apparatus 1000 is similar to the subsea drain apparatus700 described with reference to FIG. 8 .

In FIGS. 11 a and 11 b , the valves 34 a, 34 b are replaced by a singlevalve unit. Here, a hinge 38 on the junction between the inlet 10 andthe bypass channel 21 is coupled to a blocking member 40. The hinge 38is manually operable by way of an electrical signal received from acontrol room on land (or an offshore facility) or at the well head. Theelectrical signal is received through an internal conduit of a subseaumbilical line 46 described with reference to FIG. 15 . In alternativeembodiments, at least one sensor for detecting a pig is disposed alongthe subsea pipe 30. When a pig is detected, the hinge 38 isautomatically operated to change the position of the blocking member 40to open the bypass channel 21. A predetermined period of time after thepig has passed the sensor, the hinge 38 is operated to close the bypasschannel 21 and open the inlet 10. In further embodiments, the hinge 38is arranged to operate automatically at predetermined times.

The blocking member 40 is of a length chosen to substantially block thebypass channel 21 in the first mode of operation and block the inlet 10in the second mode of operation. Additionally, the blocking member 40can be formed from a material that is substantially impermeable toeither a liquid or gas phase in the multiphase flow. Therefore, in thefirst mode of operation, multiphase flow is directed through the drain100 but not the bypass channel 21. In the second mode of operation a pigis directed through the bypass channel 21 but not the drain 100.

Similarly to as described with reference to FIG. 9 , the drain apparatus1000 may further include a second valve unit arranged to alternatelyblock the gas outlet 15 and the bypass channel 21.

FIG. 12 shows a part of a subsea pipeline 1100 according to anembodiment of the present invention. The subsea pipeline 1100 includes asubsea drain apparatus 700 coupled to open ends of a subsea pipe 30. Theopen ends of the bypass channel 21 are coupled to the open ends of thesubsea pipe 30. Coupling may comprise welding, bolting, or any otherwell-known means for producing an air-tight seal between vessels coupledsubsea. In FIG. 12 , the ends of the bypass channel 21 are welded to theends of the subsea pipe 30 at weld points 32. A gasket or seal may alsobe disposed between the ends of the subsea pipe 30 and the bypasschannel 21 to further prevent the multiphase flow from escaping thesubsea pipeline 1100.

The internal diameter of the bypass channel 21 and the internal diameterof the subsea pipe 30 are approximately equal. Therefore, a pig, such asa pipe inspection pig, is able to travel through both the bypass channel21 and the subsea pipe 30 uninterrupted.

While a drain apparatus 700 according to FIG. 8 is shown in thisembodiment, this is for illustrative purposes only, and any drainapparatus as described with reference to FIGS. 9 to 11 b may be usedinstead of the drain apparatus 700 of FIG. 8 in alternative embodiments.

The subsea pipeline 1100 includes a pump 42 coupled to the liquid outlet14. The pump 42 according to this embodiment forms part of the drainapparatus 700 prior to installation of the drain apparatus 700 on theseabed. In other words, the pump 42 becomes integrated with subseapipeline 1100 upon the ends of the bypass channel 21 being coupled tothe subsea pipe 30. Alternatively, the pump 42 may be pre-installed onthe seabed, and the liquid outlet 14 is coupled to the pump 42 after thedrain apparatus 700 has been laid.

The pump 42 may be continually active to draw liquid from the drainapparatus 700. Alternatively, the pump 42 may be activated by the liquidlevel sensor 22 detecting that level of liquid in chamber 12, reservoir16 or liquid outlet 14 exceeds a threshold.

At one inlet, the pump 42 is coupled to the liquid outlet 14 of thedrain apparatus 700. At another inlet, the pump 42 is coupled to aliquid removal line 44 coupled at its other end to another pump. Thepumps 42 work in unison to effectively draw liquid from plural drainapparatuses. In other words, each drain apparatus 700 acts as a pumpingstation for moving liquid to the next drain apparatus 700 in the system.Using a plurality of pumps 42 disposed along the pipeline 1100 reducesthe pumping overhead versus the prior art, where a single or a pluralityof pumps are installed at the end of the pipeline. Furthermore, systemredundancy is improved, which is particular important in inaccessiblesubsea environments. An outlet of the pump 42 is coupled to a liquidremoval line 44 for transporting the extracted liquid to a processingfacility on the land (or an offshore facility).

The liquid removal line 44 shown in FIG. 12 is a separate subsea pipe.However, in other embodiments, the liquid removal line 44 is an internalconduit of a subsea umbilical line 46.

Rather than there being a pump 42 disposed between separate liquidremoval lines 44, the pump 42 may be disposed within a single liquidremoval line 44.

FIG. 13 shows a system view of a more specific embodiment of the subseapipeline 600 described with reference to FIG. 7 . Here, two subsea drainapparatuses 400 having a hydrate inhibitor injection port 24 are shownintegrated with a subsea pipe 30. It would be readily apparent that thenumber of drain apparatuses 400 is not intended to be limiting and moreor fewer subsea drain apparatuses 400 may be integrated with the subseapipe 30.

The hydrate inhibitor port 24 is coupled to a hydrate inhibitorinjection line 26. In the embodiment shown in FIG. 13 , the hydrateinhibitor line 26 is an internal conduit of a subsea umbilical line 46.In other embodiments, the hydrate inhibitor line 26 is a separate subseapipe.

Moreover, the liquid removal line 44, coupled to the pump 42 and to theliquid outlet 14, is also an internal conduit of the subsea umbilicalline 46. In other embodiments, the liquid removal line 44 is a separatesubsea pipe.

In the embodiment shown in FIG. 13 , a single pump 42 is connected tothe umbilical line 46 at one end of the subsea pipeline 600. Morespecifically, the pump 42 is connected to the internal conduit of thesubsea umbilical line for carrying extracted liquid to a processingfacility on the land. In alternative embodiments, each subsea drainapparatus 400 includes a pump 42 coupled to the subsea umbilical line46.

FIG. 14 shows a system view of a more specific embodiment of the subseapipeline 1100 described with reference to FIG. 12 . Here, two subseadrain apparatuses 700 having a hydrate inhibitor injection port 24 (asdescribed with reference to FIG. 4 as being compatible with any subseadrain or drain apparatus) are shown integrated with a subsea pipe 30. Itwould be readily apparent that the number of drain apparatuses 700 isnot intended to be limiting and more or fewer subsea drain apparatuses700 may be integrated with the subsea pipe 30.

Each subsea drain apparatus 700 has a liquid outlet 14 coupled to aninlet of a pump 42. In other words, there are an equal number of pumps42 and liquid outlets 14. In alternative embodiments, the liquid outlets14 all filter into the same liquid removal line 44, and pumps 42 eitherinterspersed randomly along the liquid removal line 44 or at the end ofthe liquid removal line 44 pump the liquid in the liquid removal line 44to the surface.

The hydrate inhibitor port 24 is coupled to a hydrate inhibitorinjection line 26. In the embodiment shown in FIG. 13 , the hydrateinhibitor line 26 is a separate subsea pipe. Moreover, the liquidremoval line 44, being coupled to a pump 42 at each subsea drainapparatus 700, is also a separate subsea pipe. In alternativeembodiments, the liquid removal line 44 and/or the hydrate inhibitorline 26 are internal conduits of a subsea umbilical line 46.

FIG. 15 shows a perspective view of a subsea umbilical line 46 accordingto an embodiment. The subsea umbilical line 46 powers and controls thesubsea pipeline. According to an embodiment, an umbilical terminationassembly is installed at each subsea drain apparatus to allow the subseaumbilical line 46 to be coupled to each drain apparatus.

The subsea umbilical line 46 includes a plurality of internal conduits47. Internal conduits 47 typically have one out of a range of diametersfrom 0.25 inches to 2.5 inches. The internal conduits 47 may beselectively used for electronic cables, such as power or control cables,or for fluid or gas transfer. According to an embodiment, one internalconduit 47 is used to as a liquid removal line 44 to transfer extractedliquid to a processing facility on the land. Alternatively oradditionally, another internal conduit 47 is used as a hydrate inhibitorinjection line 26 to provide hydrate inhibitor from a reservoir on landto each drain apparatus.

FIG. 16 shows a gathering system 1200 including a subsea pipeline 600according to an embodiment. The gathering system 1200 includes aproduction gas reservoir 48. In alternative embodiments, the reservoir48 is an oil reservoir. A well head 50 is used to draw the productiongas, which is a multiphase flow, from the reservoir 48 and the reservoirpressure drives it through a pipeline 600. Although a pipeline 600according to the embodiments described with reference to FIG. 7 isshown, any pipeline incorporating subsea drains along its length may beused to achieve the advantages described herein.

The pipeline 600 terminates at a processing facility 52 on the land oran offshore facility. The processing facility 52 receives production gasthrough the pipe 30, as well as liquid through the liquid removal line44. The processing facility 52 purifies the liquid so that it can berecycled or deposited without causing environmental damage. Theprocessing facility 52 or another land-based facility in communicationwith the pipeline 600 includes a pig launcher for sending pigs throughthe pipeline 600 to inspect, repair or clean the pipeline 600.

Two types of subsea drain apparatuses are used in the gathering system1200—shut-down liquid drains 210 and operational liquid drains 220. Ashut-down liquid drain 210 is installed at significant geographical lowpoints. Only one shut-down liquid drain 210 is shown in FIG. 16 , butthis is not intended to be limiting. More than one shut-down liquiddrain 210 may be installed at the same geographical low point, and/or ashut-down liquid drain 210 may be installed at each geographical lowpoint. Therefore, liquid drop out caused by the cooling effect on shutdown of the gathering system 1200 can be removed from the pipeline 600before subsequent start up.

With reference to FIG. 18 , operational liquid drains 220 are locatednear the reservoir 48 in order to remove the liquid drop out caused bythe ambient temperature. Furthermore, operational liquid drains 220 arelocated on the upward or downward slopes of topographical features thatinduce liquid drop out in the gathering system 1200. Therefore, theposition of operational liquid drains 220 is not restricted to beingclose to the well head, and they can be positioned at any point alongthe length of the subsea pipeline 600. The drain apparatuses describedthroughout this document are capable of operating effectively whenlocated at substantial distances from the well head 50 while providingthe described advantages. For example, in a 160 km subsea pipeline 600,a first drain apparatus can be positioned 200 m from the well head 50 toprovide a continuously piggable pipeline while increasing the distancethat production gas can be transported.

In an exemplary embodiment, the operational liquid drains 220 forextracting liquid due to topological effects are disposed about 15% ofthe way along the slope when measured from the bottom of the slope.However, to obtain the full benefit of the operational liquid drains220, their position depends on the angle of the slope relative to thehorizontal plane (i.e. the gradient or inclination of the slope),additional liquid holdup produced by the gradient as a result oftemperature and pressure changes (expressed as a percentage), pressure,flow rate, and composition of the multiphase flow. Generally, as thegradient increases, the lower down the slope the operational liquiddrain 220 should be disposed. The position of each drain can bedetermined according to the liquid holdup in relation to the gradientthat causes a slugging regime. This enables each drain to be disposed ata point along the gradient at which liquid holdup in the subsea pipelinewould otherwise cause slugging to occur. Additionally, the number ofoperational liquid drains 220 and their location can be determinedaccording to both the design flowrate and required turn down flowrate ofthe gathering system. The number and location of the operational liquiddrains 220 can be adapted according to different flowrates.

As shown by the dashed line in FIG. 17 , one shut-down liquid drain 210disposed at the bottom of a gradient has a negligible effect on theliquid content in an inclined subsea pipe 30 positioned on the gradientin relation to gradient limits on the pipeline for geotechnical andstability reasons (for example, it is not possible to lay subseapipeline at gradients greater than about 4o degrees because it would bestructurally unstable). The shut-down liquid drain 210 is primarilyuseful when the system 1200 is shut down and the flow ceases.Investigations by the inventors have revealed the surprising result thatan operational liquid drain 220 partway along the gradient has a muchlarger impact on liquid content in the subsea pipe 30, as shown by thesolid line in FIG. 17 .

Both shut-down liquid drains 210 and operational liquid drains 220 maytake any form for draining liquid from the pipeline 600. Preferably, toachieve all of the advantages described herein, the shut-down liquiddrains 210 and the operational liquid drains 220 comprise the drainapparatuses described with reference to FIGS. 2 a to 6 and 8 to 11 b.

FIG. 20 illustrates a pig passing through a drain apparatus for removingliquid from a multiphase flow in a subsea pipeline, according to anembodiment of the present invention. The drain apparatus comprises afirst channel 12 for carrying a multiphase flow comprising liquid andgas phases, and liquid extraction means 16 for extracting the liquidphase from the multiphase flow in the first channel 12, the liquidextraction means 16 comprising at least one opening 18 formed in a wallof the first channel 12 to permit liquid to be extracted through the atleast one opening. The internal diameter of the first channel, d, issubstantially the same as an internal diameter of a subsea pipe arrangedto carry the multiphase flow in the subsea pipeline.

In the present embodiment, the distance w between the furthestdownstream point of the at least one opening 18 and the furthestupstream point of the at least one opening 18 is configured to enable apig to be driven through the first channel by a pressure differentialwithin the first channel. To put it another way, the at least oneopening 18 can be configured such that a pressure differential can bemaintained across the pig 800 as the pig 800 passes through the drainapparatus. The distance w can be less than the total length of the pig800, such that the multiphase flow cannot bypass the pig by flowing outof the first channel 12 at the furthest upstream point of the opening 18and re-entering the first channel 12 at the furthest downstream point ofthe opening 18. If this were to happen, then the pressure differentialacross the pig 800 would decrease. Depending on the speed at which thepig is travelling and the frictional force between the cups 801, 802 ofthe pig and the inner surface of the first channel 12, it could bepossible for the pig to come to a halt and become stuck within the drainapparatus.

In the present embodiment the distance w between the furthest downstreampoint of the at least one opening 18 and the furthest upstream point ofthe at least one opening 18 is configured to be less than 1.5 times theinternal diameter d of the first channel 12, such that a pig 800 with alength of 1.5d can be driven through the first channel by a pressuredifferential within the first channel 12. In some embodiments thedistance w can be smaller, for example less than 0.8d to allow pigs witha minimum length of 0.8d to be driven through the first channel 12.

Referring now to FIGS. 21, 22 and 23 , a drain apparatus is illustratedaccording to a further embodiment of the present invention. Like theembodiment described above with reference to FIG. 6 , the drainapparatus 2100 of the present embodiment comprises liquid extractionmeans in the form of a first chamber 2112 a and a second chamber 2112 b.The first and second chambers 2112 a, 2112 b can each be referred to asa liquid extraction chamber. In the present embodiment the first chamber2112 a and the second chamber 2112 b are spaced apart along the channel2120, but in other embodiments the first 2112 a and the second chamber2112 b could be formed from a single chamber divided by a baffle, asdescribed above in relation to FIG. 6 .

At least one first inlet 2111 a is disposed in the first chamber 2112 a,and at least one second inlet 2111 b is disposed in the second chamber2112 b. The first inlets 2111 a and second inlets 2111 b are of a lengthless than the length of a pig, such that when a pig is travellingthrough the apparatus, the multiphase flow cannot bypass the pig byflowing out of the channel 2120 through the first inlet 2111 a and backinto the channel 2120 through the second inlet 2111 b.

A first opening 2118 a is formed in the wall of the first chamber 2112 aat a point lower than the lowest of the first inlets 2111 a. The firstopening 2118 a may be formed in the bottom of the first chamber 2112 a.A second opening 2118 b is formed in the wall of the second chamber 2112b at a point lower than the lowest of the second inlets 2111 b. Thesecond opening 2118 b may be formed in the bottom of the second chamber21112 b.

In the present embodiment, unlike the one shown in FIG. 6 , the firstand second openings 2118 a, 2118 b are not fluidly coupled by a singleconduit. Instead, in the present embodiment the one or more firstopenings 2118 a are connected to one or more first storage tanks 2131 aby one or more first conduits 2132 a, and the one or more secondopenings 2118 a are connected to one or more second storage tanks 2131 bby one or more second conduits 2132 b. The first conduits 2132 a and thesecond conduits 2132 b are disposed outside of the first chamber 2112 aand the second chamber 2112 b.

Raising the point at which the first conduit 2132 a enters therespective first storage tank 2131 a can help to stop the first conduit2132 a from being blocked by liquid contained in the first storage tank2131 a, by raising the entry point of the first conduit 2132 a above thewaterline. In the present embodiment each first conduit 2132 a entersthe respective first storage tank 2131 a at a point near the top of thefirst storage tank 2131 a.

In the present embodiment two of each of the first and second storagetanks 2131 a, 2131 b are provided, but in other embodiments a differentnumber of first and second storage tanks 2131 a, 2131 b may be used. Byincreasing the number of storage tanks provided, the storage tanks canbe placed alongside one another, i.e. arranged laterally, as opposed tohave a single large storage tank of greater height. Accordingly,providing a plurality of storage tanks can increase the storage capacitywithout increasing the overall height of the structure, makinginstallation easier. Positioning storage tanks on opposite sides of themain pipeline can also assist during installation by helping to balancethe structure as the drain apparatus is lowered through the watercolumn, having been welded to the pipeline. A further benefit of havingtwo or more storage tanks is that the efficiency of the liquid/gasseparation can be increased, by lowering the gas flow and aidinggravity-based separation.

The first and second storage tanks 2131 a, 2131 b act as reservoirs inwhich further liquid/gas separation can occur. In the presentembodiment, each of the first and second storage tanks 2131 a, 2131 b isfurther connected back to the main channel 2120 by a respective first orsecond gas conduit 2133 a, 2133 b. The first and second gas conduits2133 a, 2133 b fluidly connect the respective storage tank 2131 a, 2131b to the main channel 2120. In the present embodiment the first andsecond gas conduits 2133 a, 2133 b exit the respective storage tank 2131a, 2131 b at a point at or near the top of the storage tank, to avoidliquid entering the gas conduit 2133 a, 2133 b. Any gas remaining in theliquid that enters the storage tanks 2131 a, 2131 b will separate fromthe liquid over time, collecting at the top of the storage tanks 2131 a,2131 b. The first and second gas conduits 2133 a, 2133 b allow this gasto be reintroduced to the multiphase flow in the main pipeline, therebyhelping to prevent a build-up of pressure in the storage tanks 2131 a,2131 b and increasing the efficiency of gas collection. One or morevalves 2117 a, 2117 b can be disposed in the first and second gasconduit 2133 a, 2133 b, to control the flow of gas in the first andsecond gas conduits 2133 a, 2133 b.

Additionally, in the present embodiment the apparatus is configured soas to support the drain at a certain height above the seabed, asdescribed above with reference to the embodiment of FIG. 8 . Thisenables the first and second storage tanks 2131 b, 2131 b for collectingand storing liquid to also be situated above the seabed, therebyremoving the need to excavate the seabed in order to accommodate theapparatus. In the present embodiment, curved sections of pipeline arewelded between the main pipeline and the channel which passes throughthe liquid/gas separators, in order to accommodate the difference inheight between the drain and the pipeline. The curved sections ofpipeline can be configured to have a sufficiently large bend radius thatthe entire apparatus will be piggable once assembled.

In the embodiment shown in FIGS. 21, 22 and 23 , the one or more firstgas conduits 2133 a may be connected to the main channel 2120 before thesecond chamber 2112 b, so that gas from the first storage tanks 2131 ais reintroduced to the main multiphase flow before it passes through thesecond chamber 2112 b. In an alternative embodiment of the drainapparatus 2400, as shown in FIGS. 24, 24 and 26 , the first and secondgas conduits 2433 a, 2433 b are connected to the main channel 2420 afterthe second chamber 2412 b, so that gas from the first and second storagetanks 2431 a, 2431 b is reintroduced to the main multiphase flow afterit has passed through the first and second chambers 2412 a, 2412 b.

By having two liquid extraction chambers arranged in series, as in theembodiments shown in FIGS. 21 to 26 , the separation efficiency acrosseach chamber can be increased. This in turn can lower the total numberof drain apparatuses that need to be installed in the pipeline, hencelowering the overall cost and complexity and increasing the operationalenvelope of the total liquid gathering system.

A configuration such as the one shown in FIGS. 21, 22 and 23 , in whichgas from the first storage tanks 2131 a is reintroduced to the mainmultiphase flow before it passes through the second liquid extractionchamber 2112 b, may be advantageous for systems in which highsuperficial gas velocities are expected within the one or more firststorage tanks 2131 a. The high gas velocities in the one or more firststorage tanks 2131 a may result in a percentage of liquid re-enteringthe main channel 2120 from the one or more first storage tanks 2131 a.In these circumstances, the amount of liquid present in the main flowcan then be further reduced by the second liquid extraction chamber 2112b, with the excess liquid being removed to the one or more secondstorage tanks 2131 b.

A configuration such as the one shown in FIGS. 24, 25 and 26 , in whichgas from the first and second storage tanks 2431 a, 2431 b isreintroduced to the main multiphase flow after it has passed through thefirst and second chambers 2412 a, 2412 b, may be advantageous forsystems which are expected to experience higher superficial liquidvelocities within an annular flow regime in the main channel 2120.Accordingly, by having gas from the one or more first storage tanks 2431a re-enter the main channel 2120 after the second liquid extractionchamber 2412 b, a stable annular flow regime can be maintained in thesecond liquid extraction chamber 2412 b. As a result, more of the totalgas flow passes through the first and second storage tanks 2431 a, 2431b, increasing the overall efficiency of gas/liquid separation.

Additionally, in the embodiment of FIGS. 24, 25 and 26 , the first andsecond storage tanks 2431 a, 2432 b are physically separate from oneanother, whereas in the embodiment of FIGS. 21, 22 and 23 , a firststorage tank 2131 a and a respective second storage tank 2131 a areformed as a single body with an internal baffle 2134 dividing the bodyinto separate first and second storage tanks 2131 a, 2131 b. Eitherarrangement is possible in any embodiment. For example, in an embodimentsimilar to the one shown in FIGS. 21, 22 and 23 , in which gas from theone or more first storage tanks 2131 a is reintroduced to the mainchannel 2120 before the second chamber 2112 b, the first and secondstorage tanks 2131 a, 2131 b may be physically separate as shown in theembodiment of FIGS. 24, 25 and 26 . Similarly, in an embodiment similarto the one shown in FIGS. 24, 25 and 26 , the first and second storagetanks 2431 a, 2431 b may be physically connected as in the embodiment ofFIGS. 21, 22 and 23 .

Furthermore, in some embodiments such as the ones shown in FIGS. 21 to26 , a MEG injection port may be provided, the MEG injection port beingconfigured to inject MEG into the main channel 2120, 2420 after thepoint at which the one or more second gas conduits 2132 b, 2432 b areconnected to the main channel 2120, 2420.

Further to the advantages described above, embodiments of the presentinvention may further provide the following advantages:

-   -   1. Subsea tie backs can be extended to much greater distances        than currently possible with prior art systems.    -   2. Significant improvements in the gathering system's 1200        operational envelope, such as lowering unstable flow and hydrate        risks.    -   3. The overall system design acts as an alternative to subsea        compression, by using the existing energy/pressure from the oil        or gas reservoir 48 more efficiently.    -   4. The arrival temperature of the pipeline 600 is increased.    -   5. The overall back pressure within the system 1200 is lowered;        this has the dual benefits of increasing the performance of the        ‘integrated production system’ (i.e. reservoir and pipeline        gathering network), by increased production plateau flowrate        and/or increased duration of plateau production.

The invention claimed is:
 1. A drain apparatus for use in a subsea gaspipeline to remove liquid from a multiphase flow in the subsea gaspipeline, the drain apparatus comprising: a first channel for carrying amultiphase flow comprising liquid and gas phases, the first channelcomprising open ends configured to be connected to open ends of thesubsea gas pipeline so as to install the drain apparatus inline with thesubsea gas pipeline; and liquid extraction means for extracting theliquid phase from the multiphase flow in the first channel, such thatthe multiphase flow exiting a dry side of the first channel containsless liquid than the multiphase flow entering a wet side of the firstchannel; and at least one injection port configured to inject a hydrateinhibitor on the dry side of the first channel such that, in use, thehydrate inhibitor is carried in the multiphase flow along the subsea gaspipeline downstream of the drain apparatus, wherein an internal diameterof the first channel is substantially the same as an internal diameterof a subsea pipe arranged to carry the multiphase flow in the subsea gaspipeline, such that a pig travelling along the subsea pipe can passthrough the first channel.
 2. The drain apparatus of claim 1, whereinthe liquid extraction means is configured so as not to permit themultiphase flow to bypass the pig as the pig passes through the firstchannel, such that a pressure differential can be maintained across thepig, optionally wherein the liquid extraction means comprises at leastone opening formed in a wall of the first channel to permit liquid to beextracted through the at least one opening, and a distance between thefurthest downstream point of the at least one opening and the furthestupstream point of the at least one opening is less than 1.5 times theinternal diameter of the first channel.
 3. The drain apparatus accordingto claim 1 installed in a subsea gas pipeline, wherein the drainapparatus is disposed partway along a gradient in the subsea pipe toreduce liquid holdup, and/or wherein the liquid extraction means is aslug catcher or a separator, and/or wherein the liquid extraction meanscomprises an inlet to receive liquid from the first channel, and achamber in fluid communication with the inlet, the drain apparatusoptionally comprising a second channel configured to bypass the firstchannel, the liquid extraction means being disposed on the secondchannel.
 4. The drain apparatus according to claim 3, further comprisingat least one valve arranged to block the inlet in a first mode ofoperation and the first channel in a second mode of operation.
 5. Thedrain apparatus according to claim 3, wherein the first channel passesthrough the longitudinal axis of the chamber, optionally wherein theinlet is formed in a wall of the first channel along the longitudinalaxis of the first channel.
 6. The drain apparatus according to claim 3,wherein the liquid extraction means comprises an outlet in fluidcommunication with the chamber for removing liquid from the drainapparatus, wherein the drain apparatus optionally comprises: first andsecond inlets formed in a wall of the first channel along thelongitudinal axis of the first channel; a baffle arranged to divide thechamber into first and second chambers, wherein the first inlet isarranged in the first chamber and the second inlet is arranged in thesecond chamber; and a conduit disposed outside the chamber and connectedto the first and second chambers to fluidly connect the first chamber tothe second chamber, wherein the outlet is arranged in fluidcommunication with the conduit wherein the drain apparatus optionallycomprises at least one valve arranged in the conduit for controlling aflow through the conduit.
 7. The drain apparatus according to claim 5,wherein the liquid extraction means comprises a reservoir in fluidcommunication with an opening formed in the bottom of the chamber,optionally wherein the opening has a diameter substantially equal to thediameter of the chamber, optionally wherein the opening extends acrossthe full width of the chamber, optionally wherein the reservoircomprises an overflow outlet formed through a side surface of thereservoir for transporting gas to the chamber, optionally wherein theoutlet is formed through the bottom of the reservoir, optionally whereinthe outlet extends into the reservoir and is formed through an uppersurface of the chamber, or wherein the outlet extends into the reservoirand is formed through an upper surface of the chamber.
 8. The drainapparatus according to claim 6, wherein the outlet is formed through thebottom of the chamber, or wherein the outlet extends into the chamberand is formed through an upper surface of the chamber.
 9. The drainapparatus according to claim 8, wherein the outlet is in fluidcommunication with a third channel, optionally wherein the third channelis an internal conduit of a subsea umbilical line or a second subseapipe, optionally wherein the drain apparatus comprises at least one pumpcoupled to the outlet and configured to receive liquid from the outletand pump the liquid to the surface, optionally wherein the chamber orthe reservoir further comprises a control mechanism configured toactivate the at least one pump when a liquid level in the chamber or thereservoir exceeds a threshold.
 10. The drain apparatus according toclaim 1, wherein the liquid extraction means comprises: a first liquidextraction chamber comprising at least one first inlet to receive liquidfrom the first channel; a second liquid extraction chamber comprising atleast one second inlet to receive liquid from the first channel, whereinthe first channel is arranged to pass through the first liquidextraction chamber before the second liquid extraction chamber; a firststorage tank arranged to receive liquid from the first liquid extractionchamber; and a second storage tank arranged to receive liquid from thesecond liquid extraction chamber.
 11. The drain apparatus according toclaim 10, further comprising: a first gas conduit connecting the firststorage tank to the first channel to permit gas flow between the firststorage tank and the first channel; and/or a second gas conduitconnecting the second storage tank to the first channel to permit gasflow between the second storage tank and the first channel.
 12. Thedrain apparatus according to claim 11, wherein the first gas conduit andthe second gas conduit are connected to the first channel after thesecond liquid extraction chamber.
 13. The drain apparatus according toclaim 11, wherein the first gas conduit is connected to the firstchannel before the second liquid extraction chamber, and the second gasconduit is connected to the first channel after the second liquidextraction chamber.
 14. The drain apparatus according to claim 10,wherein the first channel is configured such that when the drainapparatus is installed in the subsea gas pipeline the first and secondliquid extraction chambers are raised above a level of the subsea pipeat either end of the first channel, such that the first and secondstorage tanks can be located at or above the level of the subsea pipeand below a level at which the first and second liquid extractionchambers are located, optionally wherein the first channel is weldeddirectly to the subsea pipe.
 15. The drain apparatus according to claim1, wherein the at least one injection port is arranged to receivehydrate inhibitor from a fourth channel, optionally wherein theinjection port extends through an outer surface of the first channelwhere the first channel protrudes from the dry side of the chamber,optionally wherein the injection port comprises at least one valve forcontrolling the rate of flow of hydrate inhibitor into the firstchannel, optionally wherein the fourth channel is an internal conduit ofa subsea umbilical line or a third subsea pipe, optionally wherein thehydrate inhibitor is at least one of Ethylene glycol [MEG], Methanol ora hydrate inhibition chemical.
 16. The drain apparatus according toclaim 1, wherein the drain apparatus comprises a first storage tankdisposed beneath the liquid extraction means, the first storage tankbeing arranged to receive liquid from the liquid extraction means,wherein in use, the drain apparatus is configured to support the liquidextraction means a certain height above the seabed so as to accommodatethe first storage tank without a need to excavate the seabed, the firstchannel further comprises curved sections between the open ends and theliquid extraction means to accommodate a difference in height betweenthe liquid extraction means and the subsea gas pipeline, and a bendradius of each of said curved sections is configured such that the pigtravelling along the subsea pipe can pass through each of said curvedsections.
 17. The drain apparatus according to claim 1, wherein thedrain apparatus comprises a plurality of storage tanks arranged toreceive liquid from the liquid extraction means, wherein the pluralityof storage tanks are disposed beneath the liquid extraction means onopposite sides of the drain apparatus, wherein in use, the drainapparatus is configured to support the liquid extraction means a certainheight above the seabed so as to accommodate the first storage tankwithout a need to excavate the seabed, the first channel furthercomprises curved sections between the open ends and the liquidextraction means to accommodate a difference in height between theliquid extraction means and the subsea gas pipeline, and a bend radiusof each of said curved sections is configured such that the pigtravelling along the subsea pipe can pass through each of said curvedsections.
 18. The drain apparatus according to claim 1, wherein theliquid extraction means comprise: a first liquid extraction chambercomprising at least one first inlet configured to receive liquid fromthe first channel; and a second liquid extraction chamber comprising atleast one second inlet configured to receive liquid from the firstchannel, wherein the first channel is arranged to pass through the firstliquid extraction chamber before the second liquid extraction chamber,wherein the drain apparatus further comprising: a first storage tankarranged to receive liquid from the first liquid extraction chamber, anda second storage tank arranged to receive liquid from the second liquidextraction chamber, wherein the first and second storage tanks aredisposed beneath the liquid extraction means and are formed as a singlebody with an internal baffle dividing the body into separate first andsecond storage tanks, wherein in use, the drain apparatus is configuredto support the liquid extraction means a certain height above the seabedso as to accommodate the first storage tank without a need to excavatethe seabed, the first channel further comprises curved sections betweenthe open ends and the liquid extraction means to accommodate adifference in height between the liquid extraction means and the subseagas pipeline, and a bend radius of each of said curved sections isconfigured such that the pig travelling along the subsea pipe can passthrough each of said curved sections.
 19. The drain apparatus accordingto claim 18, wherein the drain apparatus further comprises: a first gasconduit connecting the first storage tank to the first channel to permitgas flow between the first storage tank and the first channel; a secondgas conduit connecting the second storage tank to the first channel topermit gas flow between the second storage tank and the first channel,wherein the first gas conduit is connected to the first channel beforethe second liquid extraction chamber such that gas from the firststorage tank is reintroduced to the first channel before the secondliquid extraction chamber, and the second gas conduit is connected tothe first channel after the second liquid extraction chamber such thatgas from the second storage tank is reintroduced to the first channelafter the second liquid extraction chamber.